Old wells, new technology in spotlight at 2005 OTC

May 9, 2005
The past and future of offshore oil and gas technology drew close attention at the 2005 Offshore Technology Conference in Houston.

The past and future of offshore oil and gas technology drew close attention at the 2005 Offshore Technology Conference in Houston.

Aging wells off the UK are showing signs of structural strain that likely will worsen, according to a study reported by the UK firm UWG Ltd.

But new technology soon will be available to keep deepwater subsea wells in good repair. ExxonMobil Corp. and its licensees unveiled a system at OTC for performing deepwater well servicing from the seabed.

Also at the conference, speakers discussed the importance of technology to exploration; offshore regulatory and operational developments in Norway, Nova Scotia, and the US; and the challenges of developing leaders and maintaining the industry’s professional workforce.

Structural integrity

Some 83% of the operators of more than 6,000 offshore wells on the UK continental shelf (UKCS) are experiencing structural integrity problems with aging wells, said officials of UWG, a unit of Acteon Group Ltd., Norwich, UK, at a press conference. The UWG officials said 87% of the operators expect problems to increase due to sales of offshore properties, extension of well design lives, and general lack of attention to system design and maintenance in the past.

A recent study of that problem by Douglas-Westwood Ltd., under commission from UWG, found that 10% of UK wells have been shut in at some point during the last 5 years. Although the North Sea is a harsh environment, the structural integrity problems encountered there “have wider implications for the global oil and gas industry,” UWG reported.

“It has confirmed our belief that, as an industry, more emphasis needs to be given to insuring the structural integrity of wells during construction and to overcoming any problems that present themselves later in a well’s lifecycle,” said Ken Burton, UWG’s managing director and vice-president of Acteon’s conductor systems division. Another part of the Acteon group is WellCut Decommissioning Services, a well-abandonment contractor.

According to the report, “Concerns surrounding the structural integrity of the facilities above the waterline-in many cases now operating beyond their design lives-are generally being addressed. But what about the subsea infrastructure, in particular the conductors and the wells?”

Findings by the Douglas-Westwood study are based on interviews with representatives from 18 operators of 6,137 wells out of the 9,196 wells in the UK North Sea. Additional data from the UK Department of Trade and Industry showed that 960 wells were suspended at the time of the report and that 32% of the wells in those waters are more than 20 years old, some more than 38 years old.

Although many oil and gas fields off the UK are in decline, strong prospects remain for sustained activity in the area, the report said. Supported by government initiatives to sustain production and maximize economic recovery, the industry is focused on reevaluating and extending the operational lives of existing wells and facilities.

“However, as the region’s operational infrastructure moves beyond its intended productive life, concerns are growing over safety, productivity, and environmental standards,” the report said. “Issues of structural integrity have therefore become increasingly pertinent concerns for industry as exploration and production activity is likely to be sustained into the next decade and beyond.

As UKCS decommissioning activity continues to be delayed, and the movement toward extending the life of mature assets and developing previously untapped reserves continues to gather momentum, an increasing reliance on existing, aging infrastructure is developing.”

The report said, “However, there seems to be no real knowledge of the implications of operating wells beyond their design lives, and particular concern surrounds safety, environmental and economic standards associated with the structural integrity of these offshore wells.”

Wells suspended

Current safety and environmental regulations have led to a growing number of UKCS wells being suspended, shut in for maintenance, or prematurely plugged and abandoned in recent times.

“The most frequently reported structural integrity problems have been found to be centralization and corrosion within the well conductor system, tubing leaks, and valve failures. Other common issues include annulus pressure, connector failure, scale, conductor wear, wellhead growth, and christmas tree leaks,” the report said. “However, it must be remembered that these are the areas that operators are able to or chose to test, and there are other factors (such as the internals of a conductor) which they cannot or do not test. In any case, such problems will rarely cause a well to be shut in long term, especially given current oil and gas prices, unless there is nothing left to produce.”

Age is the primary cause of structural integrity problems with UKCS wells. “The combination of erosion, corrosion, and general fatigue failures associated with prolonged field life, particularly within wells exceeding their design lives, together with the poor design, installation, and integrity-assurance standards associated with the aging well stock, is believed to have led to an increased frequency of problems. These problems can be further exacerbated by increasing levels of water cut, heat treating, and gas lift later in field life,” the report said.

However, it said, “Athough age is undoubtedly a significant issue, if it is managed correctly it should not be a cause of structural integrity problems which may restrict, or indeed cease, production.”

Sales of aging assets to new owners mean the potential loss of asset-specific knowledge and cost-cutting in the mature phase of production. “It remains to be seen how successful the new operators will be in producing the associated wells and facilities beyond their intended design lives,” said the report.

“While the current expansion of workover and intervention activity-largely being carried out by independent operators on recently acquired aging assets-may serve to restrict any major increase in the impact of structural integrity problems, the question becomes the coverage achieved by these programs and the standards which operators are currently working to meet,” the report said. Furthermore, it said, the “proliferation of subsea technology has created particular concerns over operational efficiency, as the high cost of subsea well intervention has restricted remedial activity should problems arise, with the value of production gained often deemed insufficient to justify the costs of intervention.”

Historically, maintenance, intervention, and workover operations on UKCS wells have been severely restricted by the substantial costs involved. Operator feedback suggests that while current technologies deployed within the inspection and remediation of structural integrity problems are comprehensive, high costs generally restrict their use.

“For while decisions on potential intervention are multidisciplinary, once all risks to safety and the environment have been addressed, decisions on whether to intervene are predominantly financial,” the report said. “Operators therefore place an emphasis on the prevention of problems rather than curing them, which in turn precipitates a requirement for a greater focus to be placed upon a well’s design, installation, and integrity assurance.”

The anticipated increase in structural integrity problems will potentially affect independent operators buying offshore properties from the majors. “There would seem to be a growing need for services in preventing such issues arising and identifying and counteracting them should they occur,” the report said.

“If intervention is required, replacement rather than remediation is generally preferred, in keeping with problems created by aging assets and reduced budgets. A general requirement for easier-to-run and more cost-effective solutions which avoid the need to incur production downtime has been identified,” it said. “One technique which is expected to have a key role in providing such solutions and challenging the prevailing attitude that intervention operations are a last resort is rigless intervention.”

Of the operators interviewed, 79% believe rigless intervention techniques will increase if the required cost reductions can be realized.

Well intervention

The system displayed by ExxonMobil and its licensees is a riserless seabed coiled-tubing technology for servicing wells completed in as much as 6,500 ft of water (OGJ Online, Apr. 30, 2005).

Click here to enlarge image

The technology uses a 380-ft vessel for lowering a 500,000 lb, 80-ft high unit consisting of an upper coiled-tubing module and lower blowout-preventer module onto the subsea tree (Fig. 1). A remote operated vehicle (ROV) controlled from the vessel assists in landing the unit on top of the well.

ExxonMobil designed the technology for servicing live wells completed with horizontal trees and 36-in. structural casing with a 112-in. thick wall. Greg Browning, ExxonMobil executive for development of the technology, said during a presentation that some modern vertical trees might accommodate the unit but that ExxonMobil had not studied that option.

No fluids are returned to the surface service vessel. All fluid or solid returns from the well work enter the flowline and are handled by the production processing facilities, such as on a floating, production, storage, and offloading (FPSO) vessel.

As now designed, the coiled-tubing module includes a reel holding 13,000 ft of 2-in. coiled tubing containing an internal wireline for logging and a 20-slot indexing carousel housing various tools for downhole servicing and logging. The carousel can accommodate 24-ft tool lengths, and the tools can be interchanged while the unit is on the well.

The coiled-tubing module also has a stripper section with six elements, two of which are active at a time. Browning said ExxonMobil did extensive work developing the elastomers and strippers to prevent the possibility of leaks while tubing is run.

A string of 238-in. by 1-in. concentric coiled tubing connects the subsea modules to the surface vessel. The inner 1-in. tubing can be used for pumping methanol to prevent hydrates.

The umbilical that provides power and communications to the ROV also provides the power and communications to the subsea modules.

ExxonMobil calls the patented system Subsea Intervention Module (SIM). It says the SIM will be able to perform interventions as much three times faster than a mobile offshore drilling unit can at as much as half the cost.

The dynamically positioned SIM vessel will be about 50% larger than standard offshore stimulation vessels. The design includes a large moonpool for deploying the SIM, a mission-control center, and accommodations for more than 100 crewmembers. The vessel also has fluid tanks, pumps, work areas, and other systems needed for subsea interventions.

The licensing joint venture of BJ Services Co. and Otto Candies LLC will operate the SIM system after completion of design and construction in about 3 years.

Technological advance

James Farnsworth, BP PLC’s technology vice-president for exploration, said the advancement of technology is crucial to meeting the increasingly difficult challenges of exploration.

Two related strategies BP uses to pursue its frontier exploration goals are to acquire pioneer acreage early before technology to develop it is available and to collaborate with contractors to develop the necessary technology when it’s needed, Farnsworth said.

For example, BP led technology development when it provided 100% of the funding ($40 million) for seismic experiments with towed streamers and worked in collaboration with Schlumberger Ltd. on a program to acquire marine seismic data through salt.

In another example, Farnsworth said, “BP alone could never have developed all the technology [needed] for Thunder Horse,” its deepwater Gulf of Mexico discovery (OGJ, May 2, 2005, p. 85). Those technologies developed over 5 years from the time BP acquired the license in 1994 to its first discovery well Jan. 1, 1999. Innovations during that time included 3D seismic, more than 100 new seabed and subsea components, fourth-generation drillships enabling the company to drill in deep water, and the first use of a 50,000 ton semisubmersible production platform.

“All those components will come together later this year,” he added.

BP also encourages the development of ideas within the company and has an Innovation Board to which company personnel can go for money to develop ideas.

Farnsworth noted the importance of computer technology to exploration advances. He said BP increased its computer capability by three orders of magnitude during 1995-2005, enabling ever-larger amounts of data to be computed in time and facilitating complex migration and other solutions.

Areas of technical challenge, Farnsworth said, include drilling problems onshore, in deep water, and in the Arctic; subsalt exploration; deep and low-quality reservoirs; areas where seismic attributes are poor; low-frequency seismic data; heavy oil; and hydrates.

As the frontiers of exploration become more difficult, he said, “technology gets harder and harder, but somehow we always manage to come up with answers.”

Marathon in Norway

Off Norway, Marathon Oil Corp. has expanded its holdings to more than 1 million acres from 49,000 acres in 2001, said Steven B. Hinchman, Marathon senior vice-president, worldwide production.

At a breakfast briefing, Hinchman applauded the Norwegian government’s cooperation on the Alvheim area development and operation plan (OGJ Online, Oct. 13, 2004).

The area lies in 125 m of water on the Norwegian continental shelf, west of Haugesund. The cycle time from development concept to production is expected to be 5 years, Hinchman said.

Alvheim production is expected to start in early 2007. Reserves are estimated at 200-250 million gross boe. Fields to be developed are Boa, Kneler, Kameleon, and East Kameleon.

“Norway continues to provide access to resource-rich areas. I’m confident that the Alvheim concept is a repeatable concept,” Hinchman said. “There has been good communication [with Norwegian officials] and no surprises.”

Operator Marathon Petroleum Norge AS let an engineering, procurement, construction, installation, and commission contract to Vetco Aibel of Norway for all topsides work on the FPSO vessel to handle Alvheim’s output. The MST Odin multipurpose shuttle tanker is being converted to an FPSO.

The Alvheim area will include five subsea drill centers, associated flowlines, oil transportation by shuttle tanker, and transportation of natural gas to the UK via a new pipeline, Hinchman said. Currently, 14 horizontal wells are planned, of which three will be multilaterals.

The drill centers will include the Vilje oil discovery, formerly known as Klegg. Hamsun field, a 2004 discovery, also is likely to tie back to the FPSO, Hinchman said.

Nova Scotia changes

Nova Scotia’s Minister of Energy Cecil P. Clarke announced at OTC a “major shift” in regulatory approach to address complaints by operators that the province “had created barriers to exploration.”

Referring to the province’s “rights issuance” process, Clarke announced a change in the former policy, which penalized license holders if they had not met work commitments on a specific block. This penalty was assessed, he said, “even if experience shows it would be better to drill on another block.” He said that outcome benefited no one.

“Everyone wants wells drilled and discoveries made,” he said. “We want to collect royalties, not penalties.”

He said existing legislation allows consolidation of licenses to help ensure wells are drilled “in the right places.”

Under the new process, the overall value of work commitments remains the same, but spending will now be “targeted at prospects that hold the most promise.”

Clarke said Nova Scotian regulators have been discussing the new approach with license holders to see if the approach would lead to more wells being drilled, “especially in deep water.” The response, he said, has been affirmative.

The provincial budget, published earlier this month, increased funding for the Department of Energy to “develop better ways to share information on our offshore prospects.”

Clarke also said the province is responding to operators’ calls for a regime “in which they can reasonably anticipate costs and approval times.”

Responding to industry’s call for the regulations to stress performance and results, Nova Scotia and other governments involved in Canada’s offshore are renewing offshore regulations “to ensure they meet modern technical standards and worldwide best practices.”

Under a memorandum of understanding signed in February, an applicant must file only one set of documents for a new offshore development, and all “regulatory reviews will happen at the same time.”

Approval times for large, stand-alone developments can now run only 9-13 months, Clarke said, maybe 6 months “if the project proposal includes established technologies, in an area with few sensitivities, with ties to existing infrastructure.” Sable project approval, he noted, required 16 months.

Governments, he said, have recently completed a public comment period on a new code of practice for seismic operations. The code will “standardize seismic approval and mitigation across Canada” and be consistent with North Sea and Gulf of Mexico requirements.

Gulf of Mexico security

All 53 large Gulf of Mexico oil and gas platforms subject to federal requirements of the Marine Transportation Security Act (MTSA) complied with and met deadlines for initial directives, a Coast Guard officer reported in a luncheon talk.

MTSA first required large facilities to establish security plans and practices, explained Capt. Ronald W. Branch, chief of marine safety, security, and environmental protection in the Coast Guard district based in New Orleans. Congress passed the law in response to the terrorist attacks of Sept. 11, 2001.

MTSA greatly increased the monitoring of vessels entering US waters and set security requirements for ships, waterside facilities, and oil and gas installations on the Outer Continental Shelf.

Having established security plans and practices based on risk assessments for individual facilities, operators of affected platforms now must conduct annual drills subject to Coast Guard inspection.

“This is a way of life and a way of doing business now,” Branch said.

Generally, facility operators and crew members must show they can recognize dangerous substances and devices, behavior likely to threaten security, and efforts to circumvent security.

They also must be able to work with other vessels and facilities during period of heightened security, prohibit admittance by unauthorized persons, screen and verify the identities of unauthorized persons, verify package security, inspect stores and goods before taking them aboard, prevent delivery of unexpected materials, screen persons arriving at the facilities and their belongings, monitor facility access points, respond to and report security incidents, and comply with maritime security directives from the Coast Guard.

Leadership panel

Successful leaders of the future oil and gas business will need to possess several key characteristics, including a strong sense of the industry’s globalization and the ability to recruit talent for top management roles, according to a panel of industry professionals and politicians.

One of the panelists, Houston Mayor and former US Deputy Energy Sec. Bill White, listed four traits for sound industry leadership.

First, said White, who after serving in the DOE founded Frontera Resources Corp. with interests in Azerbaijan, “The energy industry has to become a good citizen.” The public needs to know the industry cares about the environment as it searches for and develops energy.

Second, he said, future leaders must understand that “the energy industry will become increasingly global” and have an increasingly international workforce. “Successful companies in the future will function without a ‘glass ceiling’” and will employ workers based on merit. Successful leaders of multinational companies will have a new way of thinking, and leaders have to discard stereotypical hiring and promotion mindsets, he said.

The third trait of a good leader, White said, is discipline. He said some “companies’ capital budgets equal their capital available.” This can’t continue, he said, adding that companies also should not “ramp up employment [on a project] only to pull the plug later on.”

Future leaders also must be genuinely interested in hiring young employees able to manage companies when current senior executives-now approaching retirement-leave the workforce.

Stressing interaction

In an unscheduled appearance on the panel, US Rep. Sheila Jackson-Lee (D-Tex.) volunteered her thoughts about leadership qualities, stressing interaction among companies and countries.

Jackson-Lee said successful leaders do not shy away from interaction. She recommended that leaders look worldwide for examples of companies and countries working together successfully. Jackson-Lee cited “oil revenue boards,” which some countries have set up to monitor funds from oil and gas operations.

“If this is found to be a good concept, let’s use it,” she said.

Olivier Appert, chairman and CEO of Institut Français du Pétrole, said the oil and gas industry’s long-term challenges include extending the lives of hydrocarbon reserves, developing cleaner processing and refining technologies, diversifying the world’s energy mix, reducing emissions and fuel consumption, and developing carbon dioxide capture and storage technology.

Also, Appert noted, producers need to increase exploration success ratios and hydrocarbon recovery rates from the current 35% to more than 50% through the use of advanced technology.

Appert acknowledged that oil companies have reduced their research and development budgets over the last few years but said that might change soon.

Gaurdie E. Banister Jr., technical director, EP Americas, Shell Exploration & Production, said the energy industry is moving toward an “engage me” world where just telling the public to “trust me,” doesn’t suffice.

“We are impacting the environment,” Banister said.

Concerning the industry’s shrinking workforce, Banister said it is “government that sets the tone” for which occupations dominate the industry. “No wonder that most of the petroleum engineering graduates come from China,” he observed.

In an unofficial survey of the industry, Banister said, 68% of the responding exploration and production companies felt there would be a shortage of petroleum engineers over the next 5 years.

Attracting the brightest

Peter Robertson, ChevronTexaco Corp. vice-chairman, said in his keynote speech at the OTC awards luncheon that the challenge for the industry is not primarily in finding and developing oil and gas fields but in finding and developing highly skilled, professional people.

“The game will be won,” Robertson said, “by those who can attract the best and the brightest.”

He noted that the average age of his company’s professionals is 47 and that an important near-term opportunity presented by the proposed Unocal Corp. acquisition is access to a skilled workforce.

The new global reach of national oil companies (NOCs) is changing the competitive landscape, he said, a future test of commercial and partnering skills. But competition from NOCs is not new, he pointed out. Some of today’s private-sector oil companies began life as NOCs.

Contributing to this report were Judy R. Clark, senior associate editor; Paula Dittrick, senior staff writer; Sam Fletcher, senior writer; Guntis Moritis, production editor; Steven Poruban, senior editor; Nina M. Rach, drilling editor; Bob Tippee, editor; and Warren R. True, chief technology editor-LNG/gas processing.